Oil production from the Organization of the Petroleum Exporting Countries (OPEC) for November rose for the sixth straight month to a record 33.86 million barrels per day (b/d), according to a survey of OPEC and oil industry officials by S&P Global Platts, the leading independent provider of information and benchmark prices for the commodities and energy markets.
The November production figure was a 320,000 b/d rise from October output and illustrates the challenge OPEC faces implementing a production cut it finalized in Vienna last week with the aim of accelerating the global oil market's rebalancing.
Many members appear to be pumping at or close to their full capacity to maximize revenues before the OPEC deal goes into force January 1.
Under that plan, the organization will, for six months, cut 1.2 million b/d from its October output level, as calculated by an average of OPEC's six secondary sources, including Platts, and freeze production at around 32.5 million b/d.
Saudi Arabia, which has committed to holding its output at 10.046 million b/d, saw its November production drop slightly to 10.52 million b/d, indicating it has a way to go before complying with its target.
Exports of Saudi crude have been high in recent months and output has defied the usual seasonal decline, even with the peak summer air conditioning season long over, though experts expect the country to return to more typical winter consumption patterns to comply with the production cut.
Iraq, OPEC's second largest producer, saw November output hold steady at 4.56 million b/d. The country had disputed secondary source estimates of its production as too low and sought an exemption from the OPEC cuts due to its war against the Islamic State.
But Iraq ultimately agreed to the OPEC plan, which calls for the country to bring production down to 4.351 million b/d, as calculated by secondary sources.
Iran, meanwhile, raised its November production slightly from October to 3.69 million b/d. Iran, which also sought an exemption from the cuts as it aimed to regain its pre-sanctions market share, is allowed to produce up to 3.797 million b/d under the OPEC plan.
Angola showed the biggest rise in production for November, but that was expected as its key Dalia field, which produces around 200,000-250,000 b/d, was scheduled to come back online after going down for maintenance for all of October.
Angola's November production was 1.7 million b/d, up 230,000 b/d from October, with small declines in export volumes offsetting the return of Dalia. Its output target of 1.673 million b/d under the OPEC plan is based on its September level, before Dalia went into maintenance.
Nigeria, exempt from the OPEC cuts as it battles militancy in the Niger Delta, saw its production remain at 1.68 million b/d in November, unchanged from October. The loss of production of key export grade Forcados, which saw a major pipeline bombed in early November, was offset by increased exports of other grades.
Traders say they expect Forcados production to remain offline for a while, with no signs of a January loading program, and the oil-rich Niger Delta remains unstable and sensitive, with chances of more militant attacks on oil infrastructure high.
Libya, also exempt from the cuts, averaged 580,000 b/d in November, up 50,000 b/d from October, as it continues to find its footing after years of civil war.
The country had been producing 600,000 b/d at the beginning of the month, according to state-owned National Oil Corporation, but a power outage November 23 caused output to fall to 523,000 b/d.
Venezuela was the only OPEC member other than Saudi Arabia to see a fall in production, as November output slid to 2.07 million b/d amid the country's economic crisis.
The Platts estimates were obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data.
For output numbers by country, click on this S&P Global Platts OPEC Production Table. You may be prompted for a cost-free, one-time-only log-in registration.
BHP Billiton has announced that it submitted the winning bid to acquire a 60 per cent participating interest in and operatorship of blocks AE-0092 and AE-0093 containing the Trion discovery located in the deep-water Gulf of Mexico offshore Mexico. PEMEX Exploration & Production Mexico (Pemex) will retain a 40 per cent interest in the blocks. Pemex estimates the gross recoverable resource to be 485 MMboe. Subject to satisfaction of conditions (including the obtaining of government approvals), it is anticipated that the relevant agreements would be finalized and signed within 90 days.
BHP Billiton’s bid for Trion includes an upfront cash payment of US$62.4 million and a commitment to a Minimum Work Program (estimated to be up to a maximum of US$320 million).
Should BHP Billiton and Pemex agree to progress the project beyond the Minimum Work Program, BHP Billiton would be required to invest the remainder of the US$570 million Minimum Work Contribution (which includes the Minimum Work Program spend) and a US$624 million cash contribution (which comprises the upfront cash payment of US$62.4 million already paid and the balance of US$561.6 million as a future carry for Pemex). BHP Billiton’s bid also includes a commitment to an additional royalty of 4%.
Steve Pastor, BHP Billiton President Operations Petroleum, said “We see attractive potential in Trion and the Perdido trend, and we are pleased to have the opportunity to further appraise and potentially develop this prospective frontier area of the deep-water Gulf of Mexico.”
“This opportunity aligns with our strategy of owning and operating Tier-1 assets and provides an opportunity for BHP Billiton to leverage its industry leading deep-water drilling, development and operational expertise to create value in Mexico.”
Hyperdynamics Corporation (OTCQX: HDYN) announces that it has signed a definitive drilling services contract with a subsidiary of Pacific Drilling SA to engage the Pacific Bora drillship to begin a drilling campaign offshore the Republic of Guinea in the second calendar quarter of 2017.
"This contract underscores our commitment to drilling our next exploration well offshore the Republic of Guinea next year," said Ray Leonard, Hyperdynamics President and Chief Executive Officer. "Since the signing of a preliminary Letter of Award with Pacific Drilling a month ago, we have also achieved several other crucial milestones that will enable us to begin drilling the Fatala-1 prospect this spring.
"Long-lead time equipment and materials that are being turned over to Hyperdynamics by former operator Tullow Oil are currently being inspected at a storage yard in Ghana before shipment to Guinea. We are in the process of tendering for the major services that will be needed for our drilling operations as well as for support services such as boat and helicopter transportation.
"We are continuing to hold discussions with prospective working interest partners, including major multinational energy companies and independents, to share project-related costs and risks and to enhance project technical competencies. We are also exploring options to raise equity through a share offering," Leonard said.
The Pacific Bora is currently located in West Africa, has just finished a contract for a major American exploration and production company. The drillship is expected to arrive shortly before the target spud date for the Fatala-1 well. Hyperdynamics' contract with Pacific Drilling enables us to include as many as three additional wells under the same favorable terms and conditions.
Hyperdynamics is an emerging independent oil and gas exploration company that is exploring for oil and gas offshore the Republic of Guinea in West Africa. To find out more, visit our website.
Murphy Oil Corporation (NYSE: MUR) announces that a joint venture ("JV") led by its Mexican subsidiary, Murphy Sur, S. de R.L. de C.V., was the high bidder and is expected to be awarded Block 5 during Mexico's fourth phase, round one deepwater auction. Under the terms of the JV, Murphy will be the operator with a 30 percent working interest ("WI"), together with PC CARIGALI MEXICO OPERATIONS, S.A. DE C.V., a wholly-owned subsidiary of PETRONAS (23.34 percent WI), Ophir Energy (23.33 percent WI) and Sierra Offshore Exploration (23.33 percent WI).
Block 5 is located in the deepwater Salinas basin covering approximately 2,600 square kilometers (1,000 square miles), and water depths in this block range from 700 to 1,100 meters (2,300 to 3,600 feet). The initial exploration period for the license is four years and includes a work program commitment of one well.
The Bureau of Ocean Energy Management (BOEM) completed its required evaluation to ensure the public receives fair market value for tracts leased in Western Gulf of Mexico Oil and Gas Lease Sale 248, held on August 24, 2016.
After extensive geological, geophysical, engineering, and economic analysis, BOEM has awarded all 24 leases on tracts covering 138,240 acres to high bidders who participated in the sale. The accepted high bids are valued at $18,067,020. BOEM accepted the 24 bids after determining that the value of each bid was sufficient to provide the public with fair market value for each tract. The highest bid accepted was $1,124,000, submitted by Exxon Mobil Corporation for East Breaks, Block 590. BHP Billiton Petroleum (Deepwater) submitted 12 of the 24 bids.
During the sale, three companies submitted 24 single bids totaling $18,067,020. No bids were received in water depths less than 800 meters or greater than 1,600 meters. By comparison, during last year’s Western Sale 246, 33 tracts received single bids totaling $22,675,212. Five of the bids were in water depths less than 800 meters and 21 were in water depths greater than 1,600 meters. For more information on Sale 248 click here.
CGG announces the delivery of near real-time imaging results for a 4,200 sq km BroadSeis 3D marine seismic survey acquired offshore Morocco. CGG delivered the very-fast-track (VFT) RTM PSDM volume to the client only 4 days after the last shot.
The 4,200 sq km BroadSeis 3D seismic survey offshore Morocco was acquired by the Geo Caspian.
This technical feat crowned an excellent operational performance by the crew of the CGG Geo Caspian who worked in a safe, collaborative and effective partnership with the client to complete the program ahead of schedule.
Jean-Georges Malcor, CEO, CGG, said: “This exceptional achievement surpasses our record last year when we delivered 1,700 sq km of fast-track depth imaging data just 9 days after acquisition for another survey offshore Morocco for the same client. It reflects the dedication of our offshore and onshore experts to go the extra mile to deliver results that continue to exceed our clients’ expectations.”
Subsea Integration Alliance has announced the industry’s first deepwater integrated subsea engineering, procurement, construction, installation and commissioning (EPCIC) multiphase boosting system award. This award, by Murphy Exploration & Production Company–USA, a subsidiary of Murphy Oil Corporation (NYSE: MUR), is for the industry’s longest deepwater subsea multiphase boosting tieback.
Building on a track record of numerous engineering studies, this is the first EPCIC project award for Subsea Integration Alliance, which was formed July 2015 between OneSubsea, Schlumberger, and Subsea 7. The scope of the contract calls for the supply and installation of a subsea multiphase boosting system for the Dalmatian Field in the Gulf of Mexico. This includes topside and subsea controls, as well as a 35 km integrated power and control umbilical. The alliance enables a turnkey integrated project from design through supply, installation and commissioning.
“OneSubsea has a strong track record of innovation, including world-leading experience in subsea multiphase boosting systems. More than 35 projects, including some 100 subsea pumps, have been delivered since 1994,” said Mike Garding, president, OneSubsea, Schlumberger. “This fit-for-purpose subsea boosting technology will improve Murphy E&P’s ultimate recovery through a cost-effective, record tieback. The innovative business model of the alliance further contributes to greater certainty of cost and return on investment.”
Subsea 7’s Chief Executive Officer, Jean Cahuzac, added, “This contract recognizes our successful alliance model that brings together Subsea 7’s SURF technology and extensive track record in delivery of large-scale complex EPCIC projects, with OneSubsea’s reservoir and subsea production, and processing systems technologies. Our alliance presents Murphy E&P with many opportunities to improve their field economics, and reduces complexity, cost and risk to achieve production objectives safely, on time and within challenging cost targets.”
Through the alliance, the organizations will work closely together across their project management teams, sharing knowledge and best practices to identify opportunities for continuous improvement while providing seamless project execution. Murphy E&P will benefit from the removal of interface and design risks associated with conventional subsea solutions. Offshore installation activities are scheduled for 2018.
Subsea Integration Alliance is a worldwide non-incorporated partnership between OneSubsea, Schlumberger, and Subsea 7 developed to jointly design, develop, and deliver integrated subsea development solutions through the combination of subsurface expertise, subsea production systems (SPS), subsea processing systems, subsea umbilicals, risers and flowlines systems (SURF), and life of field services. Its goal is delivering complementary technology and expertise that help customers extend field life and lower production costs, ensuring greater certainty of recovery and return on the investment.
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) announces the award of a sizeable contract by Woodside Energy Ltd for the Greater Western Flank Phase 2 Project, offshore Australia.
The Greater Western Flank is located on the North West Shelf of Australia, 60 km southwest of the Goodwyn Alpha (GWA) platform. The contract scope comprises the subsea tie-back of adjacent fields to the GWA platform, including the installation of manifolds, umbilicals and spool pieces, together with the pre-commissioning of the system.
Project management and engineering will commence immediately from Subsea 7's office in Perth, Australia, with offshore operations scheduled to commence in 2018.
Andy Woolgar, Managing Director, Australia and New Zealand, said: "We are delighted to have been awarded this project from Woodside Energy Ltd. This is the fourth award from Woodside in recent times, and we are pleased to be able to continue this strong working relationship."
(1) Subsea 7 defines a sizeable contract as being between USD 50 million and USD 150 million.
BP has sanctioned the Mad Dog Phase 2 project in the United States, highlighting its long-term commitment to the country despite the current low oil price environment.
Mad Dog Phase 2 will include a new floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Oil production is expected to begin in late 2021.
Photo credit: BP
“This announcement shows that big deepwater projects can still be economic in a low price environment in the U.S. if they are designed in a smart and cost-effective way,” said Bob Dudley, BP Group Chief Executive. “It also demonstrates the resilience of our strategy which is focused on building on incumbent positions in the world’s most prolific hydrocarbon basins while relentlessly focusing on value over volume.”
In 2013, BP (operator, with 60.5 percent working interest) and co-owners, BHP Billiton (23.9 percent) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6 percent), decided to re-evaluate the Mad Dog Phase 2 project after an initial design proved too complex and costly. Since then, BP has worked with co-owners and contractors to simplify and standardize the platform’s design, reducing the overall project cost by about 60 percent. Today, the leaner $9 billion project, which also includes capacity for water injection, is projected to be profitable at or below current oil prices.
“Mad Dog Phase 2 has been one of the most anticipated projects in the U.S. deepwater and underscores our continued commitment to the Gulf of Mexico,” said Richard Morrison, president of BP’s Gulf of Mexico business. “The project team showed tremendous discipline and arrived at a far better and more resilient concept that we expect to generate strong returns for years to come, even in a low oil price environment.” While BP has reached a final investment decision (FID) on Mad Dog Phase 2, BHP Billiton and Chevron, for the Union Oil Company of California interest, are expected to make a final investment decision in the future.
BP discovered the Mad Dog field in 1998 and began production there with its first platform in 2005. Continued appraisal drilling in the field during 2009 and 2011 doubled the resource estimate of the Mad Dog field to more than 4 billion barrels of oil equivalent, spurring the need for another platform at the field. The second Mad Dog platform will be moored approximately six miles to the southwest of the existing Mad Dog platform, which is located in 4,500 feet of water about 190 miles south of New Orleans. The current Mad Dog platform has the capacity to produce up to 80,000 gross barrels of oil and 60 million gross cubic feet of natural gas per day.
BP plans to add approximately 800,000 net barrels of oil equivalent per day of new production globally from projects starting up between 2016 and 2020.
Statoil has been awarded blocks 1 and 3 in the Saline Basin in the Deepwater exploration tender in the Mexican Round 1.
The blocks cover an area of about 5,650 km2 (approx. 2,200 square miles) in the largely unexplored deepwater areas of the Saline Basin. Statoil will be the operator of blocks 1 and 3, at 33.4% equity, with partners BP and Total participating equally with the remaining equity.
Map image: Courtesy: Statoil
The licenses were awarded in a competitive bid round. A total of 10 deepwater blocks were on offer, with four in the Perdido Area and six in the Saline Basin.
The blocks awarded are in water depths ranging from about 900 – 3,200 meters. The bid round is Mexico’s first ever tender for deepwater exploration acreage.
“Mexico’s opening presents the industry with great opportunities, so we are pleased to secure an early position. The award grants Statoil access to significant frontier acreage in an underexplored part of offshore Mexico. The blocks are virtually untested, with considerable subsurface uncertainty, but with play-opening potential,” says Tore Løseth, Statoil’s vice president for exploration in the US and Mexico.
The winning bids for both blocks consisted of an additional royalty of 10% (on potential future revenues) and an additional work program equivalent to 1 biddable well per block. Each block also has a minimum work program as defined by the authorities, including a variety of geological activities but no required wells.
“The licenses awarded reinforces Statoil’s exploration strategy of early access at scale. This further strengthens and develops the optionality in Statoil’s long-term international portfolio,” says Løseth.
“With the Deepwater tender bringing Mexico’s historic Round 1 to a conclusion, we are starting to see the fruits of Mexico’s comprehensive energy reform. Statoil has a long-term perspective in Mexico, and we look forward to contributing to developing the energy sector by assessing the blocks awarded,” says Løseth.
Statoil has had a representative office in Mexico City since 2001.
Total has been awarded exploration licenses on 3 Blocks in offshore Mexico, following the country’s first competitive deep water bid round.
Total will be operator of Block 2 in the Perdido basin with a 50% interest, while ExxonMobil has the remaining 50%. The block covers a surface area of 2,977 square kilometers at water depths ranging from 2,300 to 3,600 meters.
In the Salina basin, Total has won a participating interest of 33.3%, alongside Statoil (33.4%) and BP (33.3%), in Blocks 1 (2,381 km²) and 3 (3,287 km²).
“With our successful bids in these promising deep water prospects, Total has seized the opportunity to benefit from Mexico’s energy reforms. Our winning bids add high-grade exploration potential to our portfolio,” said Arnaud Breuillac, President Exploration & Production at Total. “We now look forward to launching exploration works and expanding our cooperation with Mexico together with our partners.”
Jacobs Engineering Group Inc. (NYSE:JEC) announced that it has been awarded a contract from Shell Offshore Inc. (RDS) for its Vito host project in the Gulf of Mexico.
Under the terms of the contract, Jacobs is delivering a front-end engineering and design package and detailed engineering for the Vito host platform topsides. Vito is located in over 4,000 feet of water in the Mississippi Canyon area of the Gulf of Mexico. The Vito host will initially handle production from the Vito subsea field being subsequently developed, with potential for future tiebacks from other fields.
In making the announcement, Jacobs Senior Vice President Petroleum and Chemicals Manuel Junco stated, “We are delighted to continue our long-standing, successful relationship with Shell. This project allows us to leverage our experience with deep-water production systems and will be a new lower cost design basis for Shell.”
Jacobs is one of the world’s largest and most diverse providers of full-spectrum technical, professional and construction services for industrial, commercial and government organizations globally. The company employs 54,000 people and operates in more than 25 countries around the world.
Up to five wells will be drilled before the Mariner A platform hook up and commissioning activity starts next summer. First oil is expected to be produced from Mariner in 2018.
Hedda Felin, managing director, Statoil Production UK said, “This is an exciting period for us as a UKCS operator as we transition from the planning phase to active offshore operations.”
“Predrilling enables production to reach plateau levels more quickly after the start of operations on Mariner A. It will also be an important learning period for us in terms of understanding the reservoir and identifying potential efficiencies for future wells, with safety and the protection of the environment being our fundamental priorities.”
The Noble Lloyd Noble, the largest jack-up rig in the world. Photo credit: Statoil
The Noble Lloyd Noble, the largest jack-up rig in the world, is currently positioned over the Mariner jacket which was installed in 2015. The first production wells will be drilled through a well deck on the jacket. Up to five wells will be drilled before the platform topside modules arrive mid-2017. In total up to 100 reservoir targets could be drilled over the lifetime of the Mariner field, based on the current development strategy.
Statoil has worked closely with major contractors Noble Drilling and Schlumberger to ensure safe and cost-effective operations. The rig contract was awarded to Noble Drilling in 2013, followed by the contract award for integrated drilling and completion services to Schlumberger in 2014. The pre-drilling campaign will support around 500 jobs in the UKCS.
The Mariner topside modules are currently under construction at Daewoo Shipbuilding & Marine Engineering Co., Ltd. (DSME) in South Korea and sailaway is expected in the first half of 2017.
Mariner is one of the largest projects currently under development in the UKCS. Contracts worth over £1billion have been awarded to date to the UK supply chain by the project.
Statoil (U.K.) Limited is the operator of Mariner with 65.11% equity. Co-venturers are J.X. Nippon Exploration & Production (UK) Limited (20 %), Siccar Point Energy (8.89%) and Dyas Mariner Limited (6%).
The Mariner field is located on the East Shetland Platform of the UK North Sea, approximately 95 miles or 150 kilometers east of the Shetland Isles. The heavy oil field has reserves estimated at more than 250 million barrels of oil with an average plateau production of around 55,000 barrels per day.
The field will provide a long-term cash-flow over a 30-year field life. Production is expected to commence in 2018.
The concept chosen includes a production, drilling and quarters (PDQ) platform based on a steel jacket, with a floating storage unit (FSU).
The steel jacket for the Mariner A platform was completed on time and within budget at the Dragados Offshore S.A. yard in Spain, and safely installed in the field in September 2015.
The Floating Storage Unit - Mariner B – is fully installed in the Mariner field with around 20 people on board.
Noble Corporation’s «Noble Lloyd Noble» jack-up rig – which will assist the drilling of Mariner wells for the initial years – was constructed in Singapore and arrived in the Mariner field earlier in November.
The rig, the largest jack up in the world, stands 215m tall.
The pipelines are installed in the Mariner field, and other subsea, umbilical, risers and flowline (SURF) operations have been completed.
BP announced, that drilling has commenced on a potential carboniferous gas play in southern North Sea block 43/26a that, if successful, could open up a new phase of development in the region.
The well, being drilled with partners Perenco and Premier, will test the potential of a deep carboniferous age horizon several hundred meters beneath the mature reservoirs produced by the Ravenspurn ST2 platform.
Photo courtesy: BP
Mark Thomas, BP North Sea regional president, commented: “This play warrants further exploration as we know the reservoir sands exist. What we don’t know is whether, if gas is found, long-term production can be proven economic from this deeply buried reservoir horizon. We’re looking forward to working with Perenco and Premier to test this concept and better understand its potential.”
During the drilling and testing phase, Perenco - as operator of the existing producing Ravenspurn field - will act as substitute operator on behalf of BP and the other license owners.
BP holds an 85% equity stake in the prospect alongside license partners Perenco (10%) and Premier (5%).
Bibby Offshore, a leading subsea services provider to the oil and gas industry, announced that it has secured a significant contract with Shell.
The campaign, due to commence in Q1 2017, will see Bibby Offshore provide engineering and subsea construction activities in the Gannet G field in the Central North Sea.
Under the agreement, Bibby Offshore will utilise its multipurpose dive support and offshore construction vessel - Bibby Polaris - and its integral 1000 tonne basket carousel to lay flexible pipe systems in water depths of approximately 95m.
Bibby Offshore Chief Executive, Howard Woodcock
The company has also collaborated with a third party operator who will carry out trenching operations after the initial workscope is complete.
In early 2016, Bibby Offshore provided construction and inspection services for Shell on assets in the Corrib Natural Gas field in the North Atlantic Ocean, successfully completing two significant contracts.
Howard Woodcock, chief executive of Bibby Offshore said: “Securing this project was a direct result of our established and successful track record with Shell. This contract will further strengthen our relationship, and highlights Bibby Offshore’s ability to consistently and successfully deliver on complex and challenging projects.”
BP announced on Tuesday, that it has acquired interests in two North Sea exploration prospects, Jock Scott and Craster, in a further demonstration of the organization’s commitment to the basin.
BP has acquired a 25% interest in the Statoil-operated licenses located to the east of Shetland, P2275 and P2097, which includes the Jock Scott prospect, and a 40% interest in the nearby P2163 and P2147 licenses. Statoil will remain the operator for all of these licenses.
Statoil and BP are planning to drill an exploration well on Jock Scott in mid-2017.
Map Image credit: Statoil
In the west of Shetland, BP has acquired a 40% interest in the north and a 30% interest in the south of the Nexen-operated license P2062, which includes the Craster prospect. Nexen will remain the operator of the license.
BP and Nexen are also planning to drill an exploration well on Craster in mid-2017.
Mark Thomas, BP North Sea Regional President commented: “Working together with companies such as Statoil and Nexen to access the North Sea’s remaining resource is an important part of our strategy to remain a material North Sea producer, investor and employer for decades to come. We look forward to working with both Statoil and Nexen on these exciting prospects.”
The North Sea is an important region for BP where it expects to sustain a significant business for the long term.
Over the next 18 months, BP plans to participate in up to five exploration wells in addition to drilling approximately 50 development wells over the next 3-4 years.
BP North Sea is set to grow UK production to around 200,000 barrels per day by 2020, with an exciting set of future investment and renewal options capable of sustaining a material business well into the 2030s.
Along with its co-venturers, BP has invested at record levels in the North Sea. In 2016, BP will still invest around $1.8bn of capital investment and $1.6bn running its operations. BP is expecting important new oil production from its major projects Quad204 and Clair Ridge in early 2017 and 2018 respectively.
BP is also investing significantly in the reliability and integrity of existing assets through an extensive renewal program.
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